The present invention relates generally to testing and evaluating a section of reservoir intersected during the well construction process. More particularly, the present invention relates to methods, systems and tools used in testing and evaluation of a subsurface well formation during drilling of the wellbore.
A reservoir is formed of one or more subsurface rock formations containing a liquid and/or gaseous hydrocarbon. The reservoir rock is porous and permeable. The degree of porosity relates to the volume of liquid contained within the reservoir. The permeability relates to the reservoir fluids"" ability to move through the rock and be recovered for sale. A reservoir is an invisible, complex physical system that must be understood in order to determine the value of the contained hydrocarbons.
The characteristics of a reservoir are extrapolated from the small portion of a formation exposed during the well drilling and construction process. It is particularly important to obtain an evaluation of the quality of rock (formation) intersected during well construction. Even though a large body of data may have been compiled regarding the characteristics of a specific reservoir, it is important to understand the characteristics of the rock intersected by a specific wellbore and to recognize, as soon as possible during the process of well construction, the effective permeability and permeability differences of the formation intersected during well construction.
The present invention is primarily directed to wellbore and formation evaluation while drilling xe2x80x9cunderbalanced.xe2x80x9d Underbalanced drilling is a well construction process defined as a state in which the pressure induced by the weight of the drilling fluid (hydrostatic pressure) is less than the actual pressure within the pore spaces of the reservoir rock (formation pressure). In a more conventional process, the well is typically drilled xe2x80x9coverbalanced.xe2x80x9d In an overbalanced drilling process, the pressure induced by the weight of the drilling fluid (hydrostatic pressure) is greater than the actual pore pressure of the reservoir rock.
During underbalanced well construction, the fluids within the pore spaces of the reservoir rock flow into the wellbore. Because flow is allowed to enter the wellbore, the fluid flow characteristics of the formation are more easily observed and measured. During overbalanced drilling, the drilling fluid may enter the formation from the wellbore. While this overbalanced flow may be evaluated to assess formation properties, it is more difficult to quantify fluid losses to the formation then it is to quantify fluid gains from the formation.
There are significant benefits obtained from the application of underbalanced well construction techniques. The rate of penetration or speed of well construction is increased. The incidence of drill pipe sticking is decreased. Underbalanced operations prevent the loss of expensive drilling fluids.
An understanding of the reservoir being penetrated during the well construction process requires direct and indirect analysis of the information obtained in and from the well. Core analysis and pressure, volume, temperature (PVT) analyses of the reservoir fluids are measurements and testing performed in a laboratory after the wellbore has been drilled. This process of formation evaluating is both costly and time-consuming. Also, it is not practical to perform core analysis and PVT studies on every well constructed within a reservoir.
During drilling of a wellbore, important information can be determined by evaluating the fluids flowing to the well surface from the formation penetrated by the wellbore. The amount of gas included in the surface flow is particularly important in evaluating the formation producing the gas. The volume of gas per unit of time, or flow rate, is a critical parameter. The rate of gas flow from the formation is affected by the back-pressure exerted through the wellbore. The information desired for a particular formation or layer is the flow rate capacity during expected flowing production pressure. The best measure of this flow rate occurs at the flowing production pressure, however, conventional gas flow measuring instruments require flow restricting orifices in performing flow measurements. Instruments using differential orifices as the basis for flow management are accurate only within a relatively narrow range of flow. Sporadic flow changes associated with penetration of different pressured or flowing formations can produce flow rates outside the accuracy limits of the measuring instrument. Surface measurements of gas flow are, consequently, performed at pressures that are different from normal flowing pressures and the results do not accurately indicate the gas flow potential of the formation. The procedures commonly employed to measure surface flow during drilling or constructing a well that restrict the flow as a part of the gas flow rate measurement reduce the accuracy of evaluations of formation capacity based upon such measurements. Conventional instruments that measure flow without restricting the flow are typically incapable of making precise measurements. These instruments, which generally use a Venturi tube in the flow line, produce unduly broad indications of flow rates.
Indirect analysis of information requires reference to well logs that are recorded during well construction. A well log is a recording, usually continuous, of a characteristic of a formation intersected by a borehole during the well construction process. Generally, well logs are utilized to distinguish lithology, porosity, and saturations of water oil and gas within the formation. Permeability values for the formation are not obtained in typical indirect analysis. An instrument for repeated formation tests (RFT) also exists. The RFT instrument can indicate potentially provided permeability within an order of magnitude of correctness. Well logging can account for as much as 5 to 15 percent of the total well construction cost.
Another means of formation testing and evaluation is the process of drill stem testing. Drill stem testing requires the stopping of the drilling process, logging to identify possible reservoirs that may have been intersected, isolating each formation of each intersected reservoir with packers and flowing each formation in an effort to determine the flow potential of the individual formation. Drill stem testing can be very time consuming and the analysis is often indeterminate or incomplete. Generally, during drill string testing, the packers are set and reset to isolate each reservoir intersected. This may lead to equipment failures or a failure to accurately obtain information about a specific formation.
Because each formation is tested as a whole, the values or data obtained provide an average formation value. Discrete characteristics within the formation must be obtained in another manner. The discrete characteristics within a layer of the formation are generally inferred from traditional well logging techniques and/or from core analysis. Well logging and core analyses are expensive and time-consuming. The extensive time involved in determining the permeability (productability) of each intersected reservoir layer in a wellbore through multiple packer movements and multiple flow and pressure buildup measurements required during a drill stem test make the process expensive and undesirable.
It is the primary object of the present invention to provide a method, system and tool for obtaining information about a formation while constructing a wellbore designed to intersect the formation. One characteristic of the formation that determines the productability of the well is permeability. During production, the fluid flows through the medium of the reservoir rock pores with greater or lesser difficulty, depending on the characteristics of the porous medium. The parameter of xe2x80x9cpermeabilityxe2x80x9d is a manager used to describe the ability of the rock to allow a fluid to flow through its pores. Permeability is expressed as an area. However, the customary unit of permeability is the millidarcy, 1 mD=0.987xc3x9710xe2x88x9215 m2. Permeability is related to geometric shape of flow passages, flow rate, differential pressure, and fluid viscosity.
Parameters such as bottomhole temperature and pressure are acquired through a bottomhole assembly during actual drilling operations and the acquired values are transmitted to the surface.
In the first method of the invention, the drilling assembly drills the wellbore to a point above the formation of interest. The measuring instruments in subsurface instruments carried by the drilling assembly are calibrated with surface measuring instruments at the well surface. The calibration is performed by evaluating injected and return fluids circulated through the closed flow system provided by the drill string assembly and the wellbore annulus. Precise qualitative and quantitative measuring instruments are provided in the calibrated system to produce accurate measurements of fluid composition, flow rates, volumes and condition of fluids injected into the drill string from the surface and fluids returning in the annulus from both the drill string and the formation.
An important feature of the present invention is the use of an ultrasonic gas flow meter in the surface measurements of gas being produced from the formation to permit unrestricted flow measurements that accurately reflect the formation""s flow characteristics. A chromatograph is used in the surface measurements of annular fluid flow to precisely identify constituents of the flow. The results of the measurement assist in making well construction decisions as the well is being drilled.
A second method of the present invention utilizes a downhole device to obtain downhole flow rates. These downhole flow rates can be compared to the flow rates determined from well surface operations. The direct measurement of downhole flow permits a more accurate permeability calculation on a foot-by-foot basis of the wellbore penetration through the formation. The need for a complex mathematical model to convert surface rates and flow properties to downhole conditions is eliminated when accurate bottomhole flow rates are obtained with a directly measuring tool.
In the methods of the invention, the bottomhole temperature and pressure may be used to determine density and/or viscosity of the produced fluids. To determine initial reservoir pressure, the drilling operation may be stopped and the well shut in to allow the pressure to buildup. Additionally, a series of flows at different differential pressure may be used to extrapolate to the initial reservoir pressure. Using these parameters, an effective permeability can be calculated for the section of formation contributing to the flow.
The measured parameters at the bit are transmitted to the well surface using fluid pulse telemetry or other suitable means. Generally, the downhole data transmission rate, relative to the rate of penetration in a reservoir, is such that the data acquisition at the bit downhole or at the surface is considered to be xe2x80x9creal-timexe2x80x9d data.
Another means of obtaining the necessary data for these novel methods of formation evaluation is to have the downhole measurements taken and stored in a subsurface memory device during actual well construction operations. After the data is acquired and stored in the memory device, it may be retrieved at a later time such as during the replacement of a worn out drill bit. This recorded data is considered xe2x80x9cnear real-timexe2x80x9d because it is not transmitted to the surface from downhole. This near real-time data from downhole is synchronized and merged with either surface measurements of hydrocarbon production or downhole measurements from the subsurface measurement instrument and used to compute the permeability and productivity of the formation intersected during the well construction process. Near real-time methods are utilized when the added expense of real-time is not warranted. The choice is usually based upon required placement accuracy of the wellbore, or when the real-time transmission is technically not feasible, or when the general economics of the reservoir prohibit use of real-time methodology.
A novel downhole flow measuring tool comprises a part of the present invention.
The downhole tool connects between the drill string and bit. Blades on the tool provide external longitudinal recesses that channel fluid across transducers mounted on the blades. The tool structure functions as a drilling stabilizer and, while rotating, positively directs the well fluid into the fluid recesses where various transducers carried by the tool are used to assist in determining flow rate and other parameters of the well fluid. This latter feature is particularly useful in horizontal drilling application where the well fluids may tend to stratify vertically.
In the preferred embodiment of the tool, several types of transducers are deployed along the tool""s external surface to provide a large number of different well fluid measurements. The increased number of measurements permits significant improvement in the accuracy of the flow rate measurements and other measurements made by the tool.